1. Field of the Invention
The invention relates to a method of controlling a downhole separator for separating hydrocarbons and water such that the hydrocarbons leave the separator flowing through a x-mas tree and a first header in a manifold, where a power fluid is used to drive a downhole turbine/pump hydraulic converter, such that the pump in the downhole turbine/pump hydraulic converter pumps separated water, and where the power fluid for the downhole turbine/pump hydraulic converter is fed through a second header in the manifold, an adjustable valve and the x-mas tree to the turbine in the downhole turbine/pump hydraulic converter. The rate of pumping is controlled by the rate of power fluid based on measures of water level in the separator, a flow split, or oil and/or water entrainment of the separated phases.
2. Description of the Related Art
One of the largest cost savings potential in the offshore oil and natural gas production industry is the zero topside facilities concept. i.e. to place as much of the equipment used for producing hydrocarbons on the seabed or downhole. Ideally this would mean the direct transport of produced hydrocarbons from subsea fields to already existing offshore platforms or all the way to shore. To achieve this, several of the topside processes and the provision of various power supplies have to be moved subsea or downhole. This preferably includes separation to intermediately stabilized crude, provide dry gas and most important remove water to reduce pipeline transportation cost and reduce hydrate formation problems associated with long distance hydrocarbon transport. Further advantages may be achieved by utilising subsea single phase or multiphase pump, gas compressor and gas liquid separation.
To achieve the above, electric and hydraulic power has to be supplied from platform or shore and distributed to the various subsea consumers. Hydraulic power has to be made available locally at the subsea production unit to serve equipment at the seabed or downhole.
Water is almost always present in the rock formation where hydrocarbons are found. The reservoir will normally produce an increasing portion of water with increase time. Water generates several problems for the oil and gas production process. It influence the specific gravity of the crude flow by dead weight. It transports the elements that generate scaling in the flow path. It forms the basis for hydrate formation, and it increases the capacity requirements for flowlines and topside separation units. Hence, if water could be removed from the well flow even before it reaches the wellhead, several problems can be avoided. Furthermore, oil and gas production can be enhanced and oil accumulation can be increased since increased lift can be obtained with removal of the produced water fraction.
A downhole hydrocyclone based separation system can be applied for both vertically and horizontally drilled wells, and may be installed in any position. Use of liquid-liquid (oil-water) cyclone separation is only appropriate with higher water-cuts (typical with water continuous wellfluid). Water suitable for re-injection to the reservoir can be provided by such a system. Cyclones are associated with purifying one phase only, which will be the water-phase in a downhole application. Using a multistage separation cyclone separation system, such as described in pending Norwegian patent application NO 2000 0816 of the same applicant will reduce water entrainment in the oil phase. However, pure oil will normally not be achieved by use of cyclones. Furthermore, energy is taken from the well fluid and is consumed for setting up a centrifugal field within the cyclones, thereby creating a pressure drop.
A downhole gravity separator is associated with a well specially designed for its application. A horizontal or a slightly deviated section of the well will provide sufficient retention time and a stratified flow regime, required for oil and water to separate due to density difference.
The separated formation water can be directed up through the wellhead, but would be best disposed of by directly re-injecting it into a reservoir below the oil and/or gas layers, to stabilize and uphold the reservoir pressure in the oil formations. Until recently this has been done by injecting the water in a separate wellbore several kilometres away from the hydrocarbon producing well. However, since an increasing number of wells now are highly deviated and extending through a relatively thin oil and/or gas producing formation, the water may be injected in the same well, some distance from the oil and/or gas producing zone.
Both the cyclone type and the gravity downhole hydrocarbon separator can be combined with either Electrical Submersible Pumps (ESP's) or Hydraulic Submersible Pumps (HSP's). The use of ESP's have increased drastically over the last years, initially for shore based wells, then on offshore platform wells and finally over the last few years on subsea wells. The ESP's are primarily used for pressure boosting the well fluid, but is also applied with cyclone separators for re-injecting produced water and boosting the separated oil to the surface. The pump is driven by asynchrone alternating current utilizing variable frequency, drive provides a variable speed motor driving the pump. Hence, a variable pressure increase can be provided to the flow. This technology is currently improving and is applied in an ever-increasing amount of problem wells. The pump motors requires electric power to be provided from the platform to which the subsea system is connected, or from onshore. One ore more subsea cables are needed as well as a set of subsea, mateable high voltage electric connectors, depending on the number of pumps. Special arrangements have to be made to penetrate the wellhead, and the downhole cable has to be clamped to the production tubing during the well completion. The pump is installed as part of the tubing and hung off the tubing hanger in the x-mas tree. Pump installed by coiled tubing is also being introduced. Limited operational time of a downhole ESP is largely caused by failure in power cable, electrical connections and electrical motors.
The HSP is rotational equipment consisting of a hydraulic powered turbine mechanically driving a pump unit. It is compact and may transfer more power compared to what is currently available with use of ESP's. The rotational speed is very high, resulting in fewer stages and a more compact unit then typical for ESP. Even though the higher rotational speed makes the bearings more sensitive to solid particles. Use of more abrasive resistance materials counteracts this problem. The application of hydrostatic bearings and continuous lubricated bearings with clean fluid supplied from surface gives a hydraulic driven downhole pump extended time in operation in a downhole environment, compared with what is currently expected of an ESP. The HSP's may be installed in the well on the tubing, by coiled tubing or by wireline operation. The pump can be driven by a conventional hydraulic motor but more likely by a turbine.
A gas reservoir normally produced a dry gas into the well inflow zone. When reservoir pressure has depleted or when well draw-down is high condensate may be formed. Water may be drawn from pockets in the reservoir formation of from a gas-water interface in the formation. The energy required for lifting produced liquid to the seabed will result in a substantial pressure drop in the production tubing. Removing the water (and/or condensate) downhole for local injection may thus either be of benefit by achieving a higher production rate determined by a resulting lower wellbore flowing pressure. Alternatively, a lower production rate can provide higher wellhead pressure which can help increasing the possible tie-back distance of a subsea field development to an existing infrastructure.
When considerable volume of gas is present in the wellbore a oil-water separator will have reduced capacity and separation performance will decline. In this case an downhole gas-liquid separator can be built-in upstream the oil-water. A gravity separator may be used, but will be ineffective when liquid is in form of mist carried with the high velocity gas flow. A centrifugal type separator will have enhance performance and enable acceleration of the gas phase past the oil-water separator thereby minimizing flow area occupied by gas.
Certain reservoir conditions and infrastructures may require flow assistance to enable production of oil and gas, and transportation from the reservoir to a production facility, economically, over the life of a field and in the environment. Generally reservoir pressure, high crude specific gravity, high viscosity, deep water, deep reservoir, long tie-back distance and high water content could put different demands and requirements on the equipment used subsea. These demands and requirements may very often vary over time.
Gas lift is a well-known method to assist the flow. As gas is injected in the flow some distance below the wellhead the commingled gas and crude specific gravity is reduced, thus lowering the wellbore inflow pressure resulting in an increased inflow rate. As pressure is reduced higher up in the production tubing, further increasing the gas volume, the gravity is even more reduced, helping the flow considerably. The gas is normally injected inthe annulus through a pressure controlled inlet valve into the production tubing at a suitable elevation.
Another method to increase lift is by introducing a downhole pump, electrical or hydraulic powered, to boost the pressure in the production tubing. The pump should preferably be positioned at the bottom of the well where gas has not been released form the oil, thus providing better efficiency and preventing cavitation problems.
Using gas for gaining artificial lift will increase frictional pressure drop since total volume flow increases with gas being brought back to host. At long tie-back distances the net effect of using gas lift becomes low when gain in static pressure is reduced by increased dynamical pressure losses. However, downhole gas lift can be accomplished locally at the production area by separating and compressing a suitable rate of gas taken from the wellfluid and distributing to the subsea wells for injection. This re-cycling of gas reduces the amount of gas flowing in the pipeline compared to having gas supplied from the host. The advantage of this can be utilized by increasing production rate from the wells, reducing pipeline size or increasing capacity by having additional well producing via the pipeline. In addition to this gas life at the riserbase will become more effective with this process configuration.
A cluster type subsea production system is typically comprising individual satellite trees arrayed around and connected to a central manifold by individual flowline jumpers. A template subsea production system consists of a compact (closely arrayed), modular, and integrated drilling and production system, designed for heavy lift vessel or moonpool/drilling rig deployment/recovery with capability for early-well drilling, ultimately leading to early production. The system is generally associated with a four-well scenario, although larger templates of 6 or 8 slots are sometimes considered, depending on the overall system requirements. In most cases the template will be equipped with a production manifold consisting of two production headers and a pipe spool connecting the headers at one end. This will allow for round trip pigging operations. In case of only one production header is used, pigging operations will require a subsea pig launcher and/or a subsea pig receiver.
The main function of the manifold is to commingle the production into one or more flowlines connected to a topside production facility, which may be located directly above or several kilometers away from the manifold. The manifold is usually a discrete structure, which may be drilling-vessel deployed or heavy-lift vessel deployed, depending on size and weight.
The production branches are tied off from the production header to the manifold import hub via a system of valves, allowing production flow to be directed into one of the production headers, or an individual tree to be isolated from the header. Alternatively, all production may be routed to one flowline allowing for the other flowline to be utilized for service operations.
In some cases the production branches also include chokes. This is depending upon the control system philosophy. Typically, the manifold will include a manifold control module. The main purpose of this is to monitor pressure and temperature and control manifold valves. Other functions may also be included, such as pig detection, multiphase flowmeter interface, sand detection and valve position indication.
An alternative is also to include the tree control modules in the manifold. This may eliminate the need for a dedicated manifold control module, as the tree control modules can control and monitor manifold functions. Again this is dependent on the overall control philosophy, number of functions, and the step-out distance.
Removing water from the well fluid late in the production lift when reservoir pressure has declined and water content has increased facilitates a lessening of fluid transport pipeline capacity. Electrical power is normally supplied to the subsea pumps via individual cables. Power may alternatively be supplied from a subsea power distribution system with a single AC or DC cable connected to the host. Hydraulic oil, chemicals, methanol and control signals are communicated to the subsea installation by use of a service umbilical. In case of using one flowline only, it can be integrated into the service umbilical together with the electrical cables providing a single flexible connection between the subsea production system and host facility. This combination may have a major cost reduction impact, especially for very long tie back distances.
Power fluid supplied subsea can also be utilized to provide downhole pressure boosting of the separated oil phase from the separator. Pressure boosting may also be by boosting the wellfluid flowing into the separator. Both ESP's and HSP's can be used to lower the wellbore flowing pressure and thereby increasing the inflow rate from the reservoir.
The conventional and Side Valve Trees have a basic philosophical difference in the sequence of installing the tubing completion. The conventional system is normally thought of for the drilling and completion scenario, which means that the tubing hanger is installed into the wellhead immediately after installation of the casing strings. This is done while the BOP (Blow-out Preventer) stack is still connected to the wellhead. The tree is then installed on the completed wellhead with a dedicated, open water riser system. Flowlines are then connected to the tree. This tends to be very efficient when it is known that a well will be completed. The down side of the conventional tree system is that any workover of the wellbore, where the completion is recovered, involves recovery of the tree. This means that flowlines and umbilical connectors, along with jumpers, must be disconnected prior to tree recovery. The tree is recovered with the dedicated riser system, then the BOP system is installed on the wellhead and only then the completion can be recovered.
A dual function x-mas tree is utilized when it is desirable to inject and produce through the same tree/wellhead. The advantage to this case is the elimination of drilling a dedicated injection well.
Downhole pressure control is required in the form of downhole safety valves. Both the inner and outer strings require safety valves. The inner string could be production or injection, and the second string (outer) would be injection. Further, if two sets of DHSV's (Downhole Safety Valves) are used then it will be assumed that each valve (inner and outer) will be controlled on an individual hydraulic function. The Horizontal Side Valve Tree provides the best solution for this configuration. The main reason for this is the advantage of being able to pull the downhole completion through the tree, which is not possible in the case of conventional trees.
The Side Valve Tree (SVT) is normally intended for a batch drilling scenario, or when planned workovers are anticipated. The SVT also is used when artificial lift means are incorporated, Such as an Electrical Submerged Pump (ESP) is either planned or used later in the field life. Vertical access is accomplished using a Blow-Out Prevention (BOP) system, or other dedicated system. Since the valves are located on the side of the spool, full bore access (usually 18¾″ diameter) is achieved. Flowlines are not disturbed during any of the workover interventions. In essence, the SVT becomes a tubing spool and the completion is installed into this spool. The down side of the SVT system is that the BOP stack must be recovered between drilling the casing and drilling the completion. The SVT is landed on the wellhead, and the BOP is re-installed on top of the SVT.
The Independently Retrievable Tree (IRT), currently being developed, combines the most desirable features of the conventional x-mas tree and the SVT. This type of tree is considered a true through-bore tree. Simply stated, the IRT allows recovery of either the tree or the tubing hanger independent of each other. Installation order of this system is also independent of each other. This means that the tubing hanger can be installed as in a conventional system, and then install the tree. The system also allows for installation of the tree first, like the SVT system, then install the completion. This type of design provides for maximum flexibility compared with the previous systems. When more equipment being installed downhole the need for regular retrieval of the completion increases, which favours the Side Valve and IR Tree.
The use of a standard production Side Valve Tree in combination with an injection spool would be considered a highly feasible solution. This solution utilizes existing technologies for the primary equipment. Tubing spools are frequently used in subsea wellhead production equipment as an alternative means for tubing hanger support. This “stacked” tree arrangement would be much the same as a tree-on-tubing spool configuration. This solution utilizes existing technologies for the primary equipment. An increased number of penetrations are required for wellbore control. Additional penetrations are an expansion of current technology, which is considered both feasible and mature.